Wednesday, May 20, 2015

Sustainability Drinks


There’s a lively group called “Sustainability Drinks” in Sydney.  They meet monthly and hear a few short presentations from people working in the sustainability industry.  I was an invited speaker last night, and this is what I said to the audience of around 120 people …

 
My name is Noel Barton, although on Fridays I call myself Geoff.  That’s a complicated story I can explain later.

 
I was originally an applied mathematician, finishing my studies with a PhD at the University of Western Australia in 1973.  I had a post-doctoral scholarship at the University of Cambridge (UK), then teaching stints at the University of Queensland and University of NSW (1975-81).  From 1981 to 2003 I worked for CSIRO, where I had a varied and good career, initially as a researcher and subsequently as leader of CSIRO’s applied mathematicians for a dozen years.  The job involved industrial applications of mathematics, a concept that occupied me for two decades.

 
I was also Director of the 5th International Congress on Industrial and Applied Mathematics, held in Sydney in 2003.  The event, the biggest mathematical conference ever held in Australia, attracted about 1900 registrations.  As a result, I’m an Ambassador of Business Events Sydney, the group with responsibility to attract conferences and exhibitions to Sydney.  That’s a big business.

 
In 2003, at age 55, I came to a point of career renewal.  Should I re-invent myself inside CSIRO?  Or break out?  As it happened, my children were fully educated and independent, and I’d had a nasty health scare a couple of years earlier.  I was able to take an early retirement option and follow my passion, which was to become an inventor, mainly in new concepts for solar thermal power generation.

 
There’s a very nice book about happiness written by Martin Seligman – you look for pleasure and gratification at the basic level (well I already had that!), then move on to exercise of your strengths and virtues (my inventive and mathematical skills) and finally to meaning and purpose (doing something worthwhile).  So the role of an inventor in solar energy really appealed.

 
I set up my own business, Sunoba Pty Ltd.  In 2004 I invented and subsequently patented a completely new thermodynamic cycle for power generation; it’s based on evaporative cooling of hot air at reduced pressure.  I made a theoretical analysis of the concept and built an experimental engine to verify the theory.  But my experimental engine had a terrible operating mechanism and I had no funds for development of the improved mechanism I’d invented.  I spent several years looking for investors, but wasn’t able to convince anyone that the engine was worthwhile.  And, to be honest, the engine was big, under-powered and needed lots of water for operation.

 
Eventually I abandoned work on the evaporation engine.  I now regard the episode as an excellent learning experience, but you might hear me wince with pain as I relate the story!

 
All was not lost however.  As part of my research program I’d been working on storage of solar thermal energy in pebble beds.  I realised that a form of the Brayton-cycle engine could be integrated with pebble bed storage to give a very promising concept for solar thermal power generation.  The expected Levelised Cost of Electricity was good, there was storage for operation after dark and the possibility for co-firing with other fuels.

 
That’s my current focus, and it’s still looking good a few years later.  With the assistance of investors, I hope to carry out experiments on a small engine later this year.  If the tests are successful, we’ll move on to bigger things. 

 
We all know about the rapid growth of PV.  Some argue that solar thermal power generation will be killed off by PV together with new forms of battery storage.  I don’t agree with that.  Solar thermal power generation has excellent storage capabilities and allows for co-firing so as to give on-demand despatchable power, even when the sun doesn’t shine and the wind doesn’t blow for weeks at a time.  I think those attributes will find a place in the 100% renewable energy systems of the future. 

 
In any case, I have a wise inventor friend who says you don’t have to save the world – just find a profitable solution in one tiny niche of the world’s vast energy system!

 
I’m always happy to have conversations about solar thermal power generation, just get in touch.

 
I’ll finish with two remarks:

 
I’m currently Convenor of the Sydney Central Chapter of the Australian Solar Council.  Our main activity is to hold Information Evenings on the 4th Tuesday of each month and we’re always looking for speakers.  Just get in touch with me if you would like to attend or speak.

 
Finally, I run a blog, which you can see at www.sunoba.blogspot.com.  In trying to attract investors for a new invention in power generation, you always get the same questions:
  • What is this technology?
  • How well does it work?
  • How much does it cost?
  • How does it compare to other technologies?

 
I needed to answer those questions, so I started to collect information on the cost of solar projects.  I have now analysed the LCOE for 52 solar projects worldwide.  The blog also analyses a couple of tidal projects and one geothermal project.  The database and results are available to all, just visit the blog, www.sunoba.blogspot.com.

You'll also see other quirky things there, such as when our fossil fuels will run out, the real cost of coal-fired power, life-cycle analyses for batteries, the cost of battery storage, beyond-Carnot heat pumps, and my favourite – if you burn 1 kg of coal, how much heat will be trapped by CO2 in the earth’s atmosphere?  And how does that compare to the heat generated by combustion?

Monday, May 11, 2015

Cost of solar power (52)


The Barcaldine Solar Farm sounds like a solar farm from central casting.

It’s located in the middle of the vast state of Queensland where the solar resource is outstanding.  The actual site is adjacent to an existing generation facility with a 38 MW gas turbine and a 15 MW steam turbine, with immediate connections to the grid available.  Lastly, the site is over 1,000 km from the next nearest generation facility, so it’s an end-of-grid installation with little competition from other generators.

The project is being developed by Barcaldine Remote Community Solar Farm Pty Ltd, which is jointly owned by Kingsway Europe SL and Elecnor Australia Pty Ltd.  Kingsway Europe is a company established to invest in renewable energy projects and other assets, securing funding from both its shareholders and the banking community.  Elecnor Australia Pty Ltd is a subsidiary of Elecnor SA, one of the world’s leading solar energy development companies.  Elecnor SA was established in 1958 and now operates in 33 countries with over 13,000 employees generating revenue in excess of over USD 3 billion each year.

For further details, see www.barcaldinesolarfarmproject.com.au.

So this project should be deliverable at the level of world’s best practice.

The timeline envisages detailed design in late 2015, final approvals and construction in 2016 and commissioning in early 2017.  At the moment, it’s planned to be 23.6 MW peak output, with annual output of 53,000 MWh.  The PV panels will be from a Tier 1 supplier (yet to be decided) and will have single-axis tracking.  The cost of the project is estimated to be between AUD 55 million and AUD 65 million.  Let me take the average, AUD 60 million.

We can now proceed to analyse the Levelised Cost of Electricity (LCOE) using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.
For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Barcaldine Solar Farm are as follows:
Cost per peak Watt              AUD 2.54/Wp
LCOE                                     AUD 129/MWh

The components of the LCOE are:

Capital           {0.094 × AUD 60×106}/{53,000 MWhr} = AUD 106/MWhr
O&M              {0.020 × AUD 60×106}/{53,000 MWhr} = AUD 23/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)
(52)      AUD 129 (Barcaldine, PV, one-axis, March 2017)

Conclusion

You can compare results with my LCOE graphic.

On this analysis, the LCOE for the Barcaldine Solar Farm is indeed excellent, broadly comparable to the best two projects I’ve analysed, namely Amanecer and DEWA.  The Capacity Factor of the Barcaldine project is 53,000 / (365 × 24 × 23.6) = 0.256, roughly what I’d expect from one-axis tracking at a good location.

In all, this project should be world-class.  I hope the developers are able to deliver according to their plans, especially in the presence of hostile government policy in Australia at the moment.
 
 
 

Wednesday, April 22, 2015

Cost of Li-ion battery storage

In a blog post last year I bemoaned the fact that it was difficult to get authoritative information on costs of storage.  My post referred to a major study by the Sandia National Laboratories [1] that gave a snapshot of costs as in mid-2013.

Now an important paper by Björn Nykvist and Måns Nilsson [2] on the cost of Li-ion battery storage in recent years has been published in Nature Climate Change.  Although the paper is paywalled, it is possible to download the authors’ data spreadsheets.  There is also plenty of information about the paper available from Green Car Congress and this blog post by the authors.

The abstract is as follows:

To properly evaluate the prospects for commercially competitive battery electric vehicles (BEV) one must have accurate information on current and predicted cost of battery packs.  The literature reveals that costs are coming down, but with large uncertainties on past, current and future costs of the dominating Li-ion technology.  This paper presents an original systematic review, analysing over 80 different estimates reported 2007–2014 to systematically trace the costs of Li-ion battery packs for BEV manufacturers.  We show that industry-wide cost estimates declined by approximately 14% annually between 2007 and 2014, from above US$1,000 per kWh to around US$410 per kWh, and that the cost of battery packs used by market-leading BEV manufacturers are even lower, at US$300 per kWh, and has declined by 8% annually.  Learning rate, the cost reduction following a cumulative doubling of production, is found to be between 6 and 9%, in line with earlier studies on vehicle battery technology.  We reveal that the costs of Li-ion battery packs continue to decline and that the costs among market leaders are much lower than previously reported.  This has significant implications for the assumptions used when modelling future energy and transport systems and permits an optimistic outlook for BEVs contributing to low-carbon transport.

The authors’ data files show that their cost estimates come from reviewed papers in international scientific journals, cited grey literature (including estimates by agencies, consultancy and industry analysts), news items of individual accounts from industry representatives and experts, and estimates for leading BEV manufacturers.

Their overall aim was to track the progress of BEV technology in general, so all variants of Li-ion technology used for BEV packs were considered.  They noted that there are still R&D improvements to be made in materials and design.  There are also expected cost reductions due to economies of scale.

Cost estimates (in 2014 USD per kWh) by Nykvist & Nilsson are shown graphically in their figure reproduced below.  I would say their work is as authoritative, timely and independent as you can get.



My observations are as follows: 
  • It’s very important to note these cost estimates are for initial capital cost; they do not take account of battery lifetime as a function of depth of discharge. 
  • I was surprised by their finding that the learning rate for Li-ion batteries is between 6% and 9% cost reduction per cumulative doubling of production.  This result is nowhere near as compelling as that for PV modules (typically 21%-22% cost reduction per doubling of production) and, in my view, contradicts commonly held perceptions.
  • Their general conclusion is that automobile battery packs for market leaders are today USD 300 per kWh and reducing at 8% annually.  If you are thinking of household or grid battery storage in Australia, you need to add a mark-up for sales to a general market (as opposed to a dedicated/captive automobile market), to convert to Australian dollars and add something for profit.  A number greater than AUD 500 per kWh seems reasonable to me.  If that number decreases at 8% annually, then you are still looking at around AUD 400 per kWh at the end of 2017.
  • Finally and for completeness, I’ll provide a link to a previous blog post referring to a paper by Barnhart & Benson [3] that discusses how much energy is stored by batteries in their entire lifetime compared to the energy required for manufacture.  That metric is Energy Stored On Invested, ESOI.

Acknowledgement

Many thanks to Anthony Kitchener for drawing my attention to paper [2].

References

[1] A A Akhil et al., “DOE/EPRI 2013 Electricity Storage Handbook in Collaboration with NRECA”, Sandia Report SAND2013-5131 (July 2013).

[2] Björn Nykvist and Måns Nilsson, Rapidly falling costs of battery packs for electric vehicles, Nature Climate Change, 5 (2015), 329-332.  See web site: 10.1038/nclimate2564

[3] C J Barnhart and S M Benson, “On the importance of reducing the energetic and material demands of electrical energy storage”, Energy Environ. Sci., 6 (2013), 1083.

Wednesday, April 8, 2015

Cost of solar power (51)

Today I’ll run the numbers on the Xina Solar One project in South Africa.  I anticipate this will be the last of four posts associated with an authoritative report I have recently been reading from the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world. 

According to internet reports such as this, the Xina Solar One project is a 100 MW parabolic trough plant in Northern Cape Province, South Africa.  Xina Solar One was awarded to Abengoa in the third round of renewable energy projects organised by the Department of Energy in South Africa.  Construction started in December 2014 and is expected to be complete in 2017.  Abengoa controls 40% of the project, the other members of the consortium are the Industrial Development Corporation, Public Investment Corporation and KaXu Community Trust.  Finance has been arranged through a large number of banks and financial institutions, as listed here.

Xina Solar One uses what is nowadays conventional technology.  Molten oil is heated to 395°C in parabolic trough collectors, and the thermal energy is transferred via heat exchanges either to steam for power generation or to molten salts for five hours storage.  The two-tank storage system contains 47,155 tonnes of solar salt, good for 1,650 MWh (thermal) of storage.  That provides for five hours operation, or 500 MWh (electrical), indicating a thermal-electrical efficiency of 500/1,650 = 0.303.

Note that these Rankine-cycle plants with thermal storage need a lot of infrastructure.  This includes the solar collectors, pumps for the heat transfer oil and molten salt, storage tanks, a boiler, heat exchangers for oil-salt, a condenser, and perhaps a facility for pre-heat and reheat of steam.  All that adds to the cost.

According to this report, the cost of the project is ZAR 9.5 billion or USD 867 million as at exchange rates of mid 2014.

What about the annual output?  As is often the case, I need to make an estimate.  The best clue comes from this press release from Abengoa, which says that the output is sufficient for 95,000 households and will avoid emissions of 348,000 tonnes CO2 per year.  Let’s suppose the emissions intensity of the South African generating fleet is 0.90 tonnes per MWh.  That implies the annual emissions are 348,000/0.9 or approximately 387,000 MWh per year.

We can now proceed to analyse the Levelised Cost of Electricity (LCOE) using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for Xina Solar One are as follows:

Cost per peak Watt              USD 8.67/Wp
LCOE                                     USD 256/MWh

The components of the LCOE are:
Capital           {0.094 × USD 867×106}/{387,000 MWhr} = USD 211/MWhr
O&M              {0.020 × USD 867×106}/{387,000 MWhr} = USD 45/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)

Conclusion

You can compare results with my LCOE graphic.

On this analysis, the LCOE for Xina Solar One is rather expensive, about twice that for Cerro Dominador in Chile (number 41 in the list above), which is also a solar thermal plant due for completion in 2017.  The LCOE for Xina Solar One is however 10% cheaper than that for Ashalim in Israel, which I analysed yesterday.


My general conclusion is that these solar thermal plants are significantly more expensive than the latest PV plants.  However both Xina and Ashalim have incorporated plans for back-up heating by fossil fuels, which implies the possibility of despatchable power generation.  The thought comes to my mind that it should be possible to make a calculation for the benefit of such co-firing.  I’ll look into that.

Cost of solar power (50)

As mentioned in the two previous posts, I’m currently reading an authoritative report by the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world. 

From my standpoint, one obvious observation from the report is how out-of-step Australia is with the rest of the world.  There are immensely powerful drivers for growth of renewables in the global economy:
  • energy security
  • new-build infrastructure in developing countries
  • pollution reduction
  • the need to reduce CO2 emissions

The effect of those drivers can be seen in the chart below, which is based on data in Figure 3 of the linked report.  It shows global trends in annual investment in renewables from 2004 to 2014.  The figures in brackets in the legend are the compound average growth rate of global investment in each technology from 2004 to 2014.


So, it is absolutely crystal clear – the global economy is investing heavily in renewables, particular solar and wind.

Is this trend likely to continue?  I refer you to a detailed article by Andy Skuce on the Skeptical Science website today.  His arguments cannot be summarised simply in one or two charts, but the crucial result is that current rates of CO2 emissions are absolutely incompatible with the need to keep the global temperature rise in industrial times to less than 2°C.  Much more investment in renewables will be required than is occurring at present.  A logical conclusion is that the investment trends shown in the chart above are likely to strengthen.

How does the Australian federal government act in the face of these trends?  The government says that switching to renewables will “clobber” our economy, that coal (and only coal!) will lift the developing world out of poverty, and that we should extract and burn every last kilogram of coal that we can. 


However, the price of coal as shown in the chart above (source) does not inspire confidence.  After a long stable period, there was a surge in the price from 2004 onwards.  Helped along by stimulus packages in various countries, notably China, the price surge lasted through the Global Financial Crisis in 2007 up until 2010, at which time the price entered a long steep decline.  Investment in coal does not look like a good strategy to me.

The government also repealed the carbon tax, closed down the Climate Commission, appointed climate change deniers to lead major reports into the economy, wants to close the Climate Change Authority and the Clean Energy Finance Corporation, and is seeking to cut the renewable energy target. 

The outcomes are evident in these quotes from the linked report:

“Small-scale solar financing declined in Australia by 11% [from 2013] as the country found itself mired in policy uncertainty, despite its robust solar resources and well-developed installation industry” (p.23)

“In Australia, utility-scale [renewables] investment plummeted to $330 million [in 2014] – from $2.1 billion in 2013 – largely due to uncertainty over the country’s renewable energy target” (p.25)

In the face of this evidence, is there any rationality or logic in the actions of the Australian government since its election in late 2013?  Well, yes, there is an ugly logic.  The likelihood is that coal will be an even worse investment strategy in the future than it is now.  Hence exploit the coal reserves as fast as possible, and never mind any long-term economic consequences or moral implications about climate change.

To me, the actions of the Australian government since election in late 2013 go beyond political patronage and ideology.  Appropriate descriptors are recklessness and irresponsibility, even economic vandalism.   The Australian people deserve better than this.  As a wealthy developed nation we should be playing a greater role in the global growth of renewables.

Well, that’s my rant for the day.  Let me now analyse the Ashalim 1 solar thermal plant in Israel.

The Ashalim solar project is based in the Negev desert in Israel.  It’s a 121 MW plant, now under construction, and due to be finished in 2017.   The project is being carried out by Megalim Solar Power, a joint venture between Alstom (25.05%), BrightSource (25.05%) and NOY Infrastructure and Energy Investment Fund (49.9%).

The technology is very similar to the Ivanpah Project in the USA (also involving BrightSource) – that is direct steam generation via heliostats and tower, with no thermal storage.  The Capacity Factor of Ivanpah is 31% (source), which implies the annual output of Ashalim will be 0.31 × 121 × 24 × 365 MWh, or approximately 330,000 MWh per year.  Back-up heating by gas is available but capped to 15% of the total output.  The cost of the project is reported as USD 821 million.

We can now proceed to analyse the Levelised Cost of Electricity (LCOE) using my standard assumptions: 
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for Ashalim are as follows:

Cost per peak Watt              USD 6.78/Wp
LCOE                                     USD 284/MWh

The components of the LCOE are:
Capital           {0.094 × USD 821×106}/{330,000 MWhr} = USD 234/MWhr
O&M              {0.020 × USD 821×106}/{330,000 MWhr} = USD 50/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50       USD 284 (Ashalim, solar thermal, 2017)

Conclusion

You can compare results with my LCOE graphic.

On this analysis, the LCOE for the Ashalim plant is rather expensive, about 2.3 times that for Cerro Dominador in Chile (number 41 in the list above), also a solar thermal plant which is due for completion around the same time.  I note that some of the project cost for Ashalim includes construction of a natural gas pipeline for back-up heating, but I doubt that omission of that cost would lower the LCOE by more than 10%.